The present invention relates generally to techniques for performing oilfield operations at a wellsite. More specifically, the present invention relates to techniques for configuring drill pipe for use in the drilling of a wellbore at the wellsite. Such drill pipe may involve, for example, tubular threaded connections on drill pipe, drill collars and/or tool joints that incorporate tapered threads between a radially outward shoulder and a radially inward shoulder, commonly referred to as a rotary shouldered (or threaded) connection.
Oilfield operations are typically performed to locate and gather valuable downhole fluids. Oil rigs are positioned at wellsites, and downhole tools, such as drilling tools, are deployed into the ground to reach subsurface reservoirs. Drill pipe strings (or drill strings), which comprise multiple drill pipes threadably connectable to one another, are typically suspended from the oil rig and used to advance a drilling tool into the Earth to drill subterranean wells. These drill pipes (or drill pipe sections) typically have tool joints (or connections) welded at each end and connected to each other to form the drill string. When drill pipe is used to drill subterranean wells, the drill pipes (or drill pipe sections) are often exposed to bending, torsional, and/or other stresses.
Oil and gas producers are attempting to drill deeper and deeper wells as they strive to maintain or increase their reserves of oil and gas. Wells 10,000 (3,050 m) to 15,000 ft. (4,575 m) deep have been common for many years. Today, wells 28,000 (8,540 m) to 30,000 ft. (9,150 m) deep are becoming more commonplace. In order to achieve the greater depths, drill pipe configurations may need to be adapted to operate in the extreme conditions. Drill pipe configurations with a wall thickness greater than 0.500″(12.7 mm) are commonly referred to as landing strings. The landing strings are typically designed to provide high tensile capacity that far exceeds the standard capacities of American Petroleum Institute (API) strings. A primary purpose may be to provide high tensile capacity for landing heavy wall casing for deepwater drilling. By using a rotary shoulder connection, the speed and robust design may increase efficiency by using the same rig handling equipment for drilling.
Up until about 2009, the tensile capacity of a landing string was typically less than about 2.0M lbs (908,000 kg). However, new requirements of the tube body have been targeted to achieve a load capacity of about 2.5M lb (1,135,000 kg). With 2.5M lbs. (1,135,000 kg) load capacity, a new connection is typically needed in order to exceed the stress levels at this higher load. The 2.0M lbs. (908,000 kg) landing strings have been successfully manufactured and deployed. However, operators may need to adjust the configuration to reach ever-increasing depths requiring landing strings with increased setting capacity. Drilling rigs, top drives and associated equipment with capacity of 1,250 tons (1,133 metric tons) are being developed. Landing strings with 2.5M lbs. (1,135,000 kg.) capacity may be required by the drilling industry.
The standard 6⅝″ (16.83 cm) FH connection with API bevel diameter (referred to herein as the Standard FH Connection) may no longer be able to maintain the connection integrity required at these levels. FIG. 1A shows such a stress distribution on a conventional connection 148 (or rotary shoulder connection) with a counterbore area 152. FIG. 1B shows a cross-sectional view of a conventional pin end 140 of the conventional connection. As shown the pin end is a Standard FH Connection. The conventional pin end 140 has a primary shoulder 150 that is configured to engage a conventional box end 142, as shown in FIG. 1A. The area of the primary shoulder 150 of the conventional pin end 140 is defined by the area between a standard bevel diameter and a standard box counterbore diameter. The bevel diameter of the Standard FH Connection is 7.703″(19.56 cm) and the standard box counterbore diameter is 6.836″(17.363 cm). FIGS. 1A and 1B show a standard bevel radius (SRb) 154 (or ½ of the standard bevel diameter) and a standard box counterbore radius (SRbm) 156 (or ½ of the standard box counterbore diameter). The Standard FH Connection has the SRb 154 of 3.852″ (9.78 cm) and the SRbm 156 of 3.418 (8.68 cm).
As shown in FIG. 1A at a make-up torque of 80,000 ft-lb. (11,070 Kg-m) the conventional connection may be overstressed upon make-up. An over-stressed cross-hatched section 155 of the conventional box end 142 is shown to cross the box end 142 at about a 45° angle to the conventional box end 142. The over-stressed cross hatched section 155 is shown on a legend 157 as being represented by the letter A. The stress levels in the legend 157 decrease from A to H as shown on the legend 157 and represented on the conventional connection in FIG. 1A.
Attempts have been made to provide pipe and joint configurations as described, for example, in U.S. Pat. Nos. 6,447,025; 6,012,744; 5,908,212; 5,535,837; and 5,853,199. Despite the development of various techniques for providing pipe joints, there remains a need to provide a drill pipe particularly suitable for applications on drill pipe used in drilling deep wells and/or having a greater tensile capacity. It is desirable that such drill pipe be configured for applications involving pipe configurations with a wall thickness greater than 0.5″(12.7 mm.). It is further desirable that such drill pipe be configured for applications involving pipe configurations with a tensile capacity of more than 2.5 M lb (1,135,000 kg.). Preferably, such drill pipe is capable of one or more of the following, among others: increased tensile strength, decreased stress levels, conformed to API standards, increased MUT, and reduced failure. The present invention is directed to fulfilling these needs in the art.